For many years coal has been mined from the earth for use as an energy source, i.e. the production of heat by the burning of the coal. A constant obstacle encountered in coal mining has been large volumes of water. A constant danger inherent in coal mining both to equipment and to men has been methane gas which is poisonous and explosive. The methane gas, unlike natural gas in place in an earth formation, comprises methane gas molecules attached to the coal which are released from the coal when the ambient pressure at the gas molecules is released to a predetermined level which varies depending upon the particular formation. For example, the methane gas is released from coal in the San Juan Basin near Farmington, N. Mex., at pressures from 80 to 160 psi. In distinct contrast, in the Black Warrior Basin near Tuscaloosa, Ala., the release pressure, desorption pressure, is about 5 to 10 psi. The depletion of oil and natural gas in recent years, particularly in the United States, has made coalbed methane gas an especially attractive secondary source of energy, particularly where the gas can be recovered economically. Two principal components of coalbeds are methane gas and formation water. The hydrostatic pressure in water in a coalbed at the site of attachment of the methane gas molecules to the coal surface, if sufficiently elevated, prevents the methane gas from detaching from the coal surface and flowing up a well penetrating a coalbed. Thus, the principal problem in the production of coalbed methane wells is the de-watering of the wells sufficiently to lower the hydrostatic pressure to a level at which the methane gas will flow to the surface in the wells. At the present time, coalbed methane gas has been produced only from the Black Warrior and San Juan Basins. The production and estimated reserves of coalbed methane gas in the United States are dramatic. The net production has been over four billion cubic meters of methane gas and the recoverable reserves in these two basins is estimated to be approximately 1.1 trillion cubic meters. The estimated reserves in the United States are believed to be in excess of 4 times the known reserves of other forms of natural gas, which is approximately 11.5 trillion cubic meters. In addition to the significant known reserves of coalbed methane gas, coalbed methane gas production is generally a low volume and low pressure situation which does not require special pressure equipment to either produce or service the wells. The wells generally are relatively shallow and once they are de-watered they produce with relatively few major maintenance problems. They typically will produce for 12 to 15 years. Significant reserves of methane gas are believed also to exist in Canada, as well as Australia, China, France, Holland and New Zealand.
Until the development of the present invention, coalbed methane wells have been de-watered to the extent necessary for the release and production of the methane gas by means of artificial lift. In the Black Warrior Basin the water has been produced from the wells using either rod or "Moyno" pumps. The wells have generally been drilled to a depth of 1,250 feet with some of the more recent wells reaching depths up to 6,000 feet. The water has been produced inside tubing while the methane gas flowed up the well annulus between the tubing and the well casing. Production in such wells has ranged from 50-1000 barrels of water per day, generally averaging 300-350. The wells have generally required from 3-12 months to de-water sufficiently for methane gas production. It has been necessary to lower the flowing bottom hole pressure across the coal seams producing the methane gas to a level of approximately 5-10 psi.
As an alternative method of de-watering wells in the Black Warrior Basin, in recent years, gas lift equipment and methods have been employed. One such method is known as "single point air injection". Air is injected down a tubing string from which the air is discharged at the bottom of well with air and water returning to the surface in the well annulus. While this method not only removes water from the well, it also has the advantage of removing frac sand and coal fines from the wellbore prior to completion of the well. There are, however, a number of problems and inefficiencies associate with this air injection method. A rig must be maintained at the wellsite until rods for a pumper installed. The air compressor required to provide sufficient air to bring the water to the surface is costly. There are no means to effectively monitor either gas production or bottom hole pressure. The flowing of the air through the tubing and the casing is extremely corrosive to the tubing and casing, and if the procedure is carried out for any prolonged period of time, they deteriorate beyond repair. When such deterioration occurs, the wells cannot be effectively re-watered prior to being placed on a rod pump. Thus, the air injection has not proven to be satisfactory for water removal in coalbed methane wells.
A second gas lift technique which has been used employs a conventional casing flow gas lift installation, which includes a tubing string including a side pocket mandrel fitted with gas lift valves disposed within an inner casing which is spaced within an outer well casing. Lift gas flows down the tubing and outwardly from the tubing through the gas lift valves into the inner casing and back to the surface through the inner annulus. The injected gas and well fluids including water are produced up the inner or secondary annulus. The methane gas is produced up the outer or secondary annulus. While this basically conventional gas lift system and method will produce a substantial amount of water, it has a number of shortcomings. As a well is unloaded, the production initially passes through the ported section of the unloading valve. The production fluid quite often contains coal fines which damages the stem and seat of the valves. As the well is unloaded to the next operating valve, a multipoint injection failure will occur because of destruction of the first valve. This failure will sharply curtail fluid lift efficiency and cause excessive and wasteful consumption of lift gas. Further, as the valves are a permanent part of the production string they cannot be retrieved and repaired without pulling the tubing string and performing a completion workover. In comparison to the use of a rod pump, this is not an economically viable alternative. And additionally, such a well installation to provide both the secondary and primary annulus is more costly than conventional rod or the usual gas lift installation.
A system and method disclosed in U.S. Pat. No. 4,509,599 issued Apr. 9, 1985 removes formation water from a well where low bottom hole pressures exist. Such system and method, however, require apparatus which could be more difficult, expensive, and time consuming to install and service than the present invention.
Thus, while the air injection method and the gas lift method utilizing primary and secondary annuli both will produce large volumes of water, they are neither a truly economical and effective way of producing coalbed methane wells.
Additional problems which have been encountered and which cannot be effectively addressed by the present available well installations and methods is that in locations such as the Black Warrior Basin a multiplicity of coal seams can be produced through a single well. For example, the number of coal seams penetrated by a single well may range from on the order of 3 to 8 vertically spaced apart anywhere from 30 or 40 feet to 200 feet. Such coal seams may start as deep as 500 to 1000 feet. Some of the coalbed seams, particularly in the Black Warrior Basin, may be only 1 to 5 feet thick. Under such circumstances, a packer cannot be placed in a well at 500 feet and be able to lower the bottom hole pressure and gas lift above the packer. The water has to be removed essentially to the total depth of the well so that there is no more than a 30 or 40 foot hydrostatic head on the coal seam formation. The multiplicity of coal seams penetrated by a well together with the economics of well installation preclude the use of packers in a well between the producing string and well casing closing off the annulus at each of the packers.